CALGARY, ALBERTA--(Marketwired - Nov. 3, 2016) - BlackPearl Resources Inc. ("BlackPearl" or the "Company") (TSX:PXX)(OMX:PXXS) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2016.

Highlights include:

  • After a rigorous review process, regulatory and environmental approval was received for our 80,000 barrel per day (bbl/d) SAGD commercial development application at Blackrod. With this approval and the success of our pilot, we will look at opportunities to accelerate development of this project;
  • Our Onion Lake thermal project continued to demonstrate that it is a top tier thermal project with production in the quarter averaging in excess of 6,400 bbl/d with an SOR of 2.5; planning and design has begun for the phase two expansion of the project that would increase capacity to 12,000 bbl/d. In addition, project production costs continued to drop during Q3 2016, averaging $8.79/boe;
  • Corporately, production averaged 10,951 barrels of oil equivalent (boe) per day in Q3 2016, a 46% increase compared to Q3 2015 volumes; the increase is attributable to the production ramp-up on the Onion Lake thermal project;
  • Net debt (bank debt less working capital) was reduced to $64 million as at September 30, 2016, which represents a net debt to funds flow ratio (a non-GAAP measure) of less than 1.2 times on an annualized basis; the Company's bank debt is $30 million lower than the peak amount in the fourth quarter of 2015;
  • Oil and gas revenues in Q3 2016 were $32.4 million, 56% higher than last year, and funds flow from operations (a non-GAAP measure) was $14.2 million, 40% higher than Q3 2015; year to date we have generated revenues of $74 million and funds flow from operations of $29 million;
  • We continued to generate reductions in our cost structure with operating and transportation costs averaging $14.24/boe during the quarter, 32% lower than in Q3 2015.

John Festival, President of BlackPearl commenting on Q3 2016 activities stated that "Our thermal projects are some of the best in the industry. The successful start-up of our Onion Lake project as well as our SAGD pilot at Blackrod demonstrates the success of our transition to a thermal heavy oil operator. We like these thermal projects because they are low decline assets that have 20+ year project lives with very attractive operating metrics. Receiving regulatory approval for Blackrod represents a significant milestone in the development of this large resource. We have started planning the expansion at Onion Lake and expect to sanction phase two in the next few months as we finalize funding for the project. We have prudently managed our operations during the downturn and as prices recover will shift our focus to development and growth of our assets."

Financial and Operating Highlights

Three months ended
September 30,
Nine months ended
September 30,
2016 2015 2016 2015
Daily production / sales volumes
Oil (bbl/d) 10,251 6,532 9,236 6,980
Bitumen (bbl/d) 565 583 567 534
10,816 7,115 9,803 7,514
Natural gas (mcf/d) 815 2,178 836 2,495
Combined (boe/d) (1) 10,951 7,478 9,942 7,930
Product pricing ($) (before the effects of hedging transactions)
Crude oil - per bbl 34.15 35.02 28.97 38.15
Natural gas - per mcf 2.10 2.88 1.72 2.69
Combined - per boe (1) 33.87 34.05 28.69 36.90
Netback ($/boe) (1) (2)
Oil and gas sales 33.87 34.05 28.69 36.90
Realized gain (loss) on risk management contracts 2.24 12.99 3.98 13.47
Royalties (4.30) (6.55) (3.61) (6.30)
Transportation (2.11) (0.97) (2.08) (1.09)
Operating costs (12.13) (20.04) (12.55) (20.84)
17.57 19.48 14.43 22.14
($000's, except per share amounts)
Oil and gas revenue - gross 32,367 20,814 73,706 73,641
Net income (loss) for the period 556 5,402 (17,711) (15,621)
Per share, basic and diluted 0.00 0.01 (0.05) (0.05)
Funds flow from operations(3) 14,202 10,156 28,977 38,064
Capital expenditures 1,753 7,870 4,775 66,843
Working capital deficiency (surplus) (3,384) (8,254) (3,384) (8,254)
Bank debt 67,000 97,000 67,000 97,000
Net Debt (4) 63,616 88,746 63,616 88,746
Shares outstanding, end of period 335,646,559 335,638,226 335,646,559 335,638,226
(1) Boe amounts are based on a conversion ratio of 6 mcf of gas to 1 barrel of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2) Netback is a non-GAAP measure that does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies.
(3) Funds flow from operations is a non-GAAP measure that represents cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital related to operations. Funds flow from operations does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. See reconciliation table between these measures under Non-GAAP Measures.
(4) Net debt is a non-GAAP measure that does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies.

Property Review

Onion Lake

Construction of the first phase of the Onion Lake thermal project was successfully completed in mid-2015 and has now been on production for just over a year. By June 2016, oil production reached name plate capacity of 6,000 bbl/d as production continued to ramp-up. During the third quarter, oil production average 6,472 bbl/d, with a steam oil ratio of 2.5. The successful start-up and on-going operations generated very good operating results, with production costs, including natural gas, under $10 per barrel during the third quarter.

We have begun planning for the expansion of the Onion Lake thermal project. The expansion would see capacity of the project doubled to 12,000 bbl/d. This expansion would include the construction of additional steam generation and oil handling facilities, water source wells, pipelines and drilling of up to 20 injection wells and 15 horizontal production wells. We estimate construction will take 12 to 15 months from the date of sanctioning and construction costs are estimated to be between $175 and $185 million, which is approximately 20% lower than the cost of the first phase of the project. The timing for sanctioning the project is dependent on finalizing funding for the project. We are currently exploring various financing options in addition to using our operating cash flows and capacity under our existing credit facility.


On September 16, 2016, the Alberta Energy Regulator and the Alberta government approved the Company's 80,000 bbl/d commercial development application for our Blackrod SAGD project, located in the Athabasca Oil Sands in northern Alberta. The approval represents a significant milestone for the Company and provides us with the certainty needed to plan the next steps in the development of this large resource. Blackrod is expected to be developed in phases, with the first phase likely to be between 10,000 and 20,000 bbl/d. We have not established timing for initial development of Blackrod as we need to secure financing to fund the development. We will consider taking on a joint venture partner to accelerate development. At December 31, 2015, our independent reserves evaluator assigned 180 million barrels of proved plus probable reserves and 566 million barrels of unrisked contingent resources (best estimate) to our Blackrod leases.

The existing SAGD pilot has provided us with important technical information that validated the applicability of the SAGD process on our lease, as well as providing valuable operating data for the design of a commercial project. The second pilot well pair continues to produces in excess of 500 bbl/d, with a steam oil ratio under three and, cumulatively, this well has produced over 400,000 barrels of oil.


No new activities were undertaken at Mooney during the third quarter. The majority of the ASP flood remained shut-in during the quarter as our primary focus at Mooney has been on our cost reduction initiatives in the field. With the recent increase in crude oil prices we are in the process of selectively bringing several wells back on production in the phase one flood area.


Oil and gas production averaged 10,951 barrels of oil equivalent per day in the third quarter of 2016, a 46% increase compared with the third quarter of 2015. The increase in oil production reflects the successful ramp-up of production from our Onion Lake thermal project partially offset by a reduction in our conventional oil production as a result of natural declines, limited new drilling activity and our decision earlier in the year to selectively shut-in some of our production at Onion Lake and Mooney due to low oil prices.

Average Daily Sales Volume

Three months ended
September 30,
Nine months ended
September 30,
(boe/day) 2016 2015 2016 2015
Onion Lake - thermal 6,472 251 5,319 85
Onion Lake - conventional 2,162 3,285 2,177 3,621
Mooney 665 2,192 807 2,523
John Lake 885 967 872 1,000
Blackrod 565 583 567 534
Other 202 200 200 167
10,951 7,478 9,942 7,930

Financial Results

Oil and gas revenues in Q3 2016 were $32.4 million, a 56% increase compared to the third quarter of 2015. The increase in revenues is attributable to a 46% increase in production volumes partially offset by a 3% decrease in our realized sales price.

Our realized oil price (before the effects of risk management activities) in Q3 2016 was $34.15 per barrel compared to $35.02 per barrel in Q3 2015. The decrease in our realized wellhead price reflects lower WTI reference oil prices in Q3 2016 compared with Q3 2015 (US$44.94/bbl vs US$46.43/bbl), and slightly wider heavy oil differentials (US$13.51/bbl vs US$13.39/bbl).

We have entered into various oil hedges to mitigate some of the negative impact of the low oil price environment in 2016. During the first nine months of 2016 we realized a gain of $10 million from our oil hedging program, which was the equivalent of adding $3.98 per barrel to our wellhead price. The table below summarizes the Company's outstanding commodity contracts as at September 30, 2016:

Subject of Contract Volume Term Reference Strike Price Type
Oil 1,000 bbls/d October 1 to December 31 CDN$ WCS CDN$ 51.15/bbl Swap
Oil 2,000 bbls/d October 1 to December 31 CDN$ WCS CDN$ 47.60/bbl Swap
Oil 2,000 bbls/d October 1 to December 31 US$ WTI US$ 65.00/bbl Sold Call
Oil 1,000 bbls/d January 1 to December 31 CDN$ WCS CDN$ 50.00/bbl Swap
Oil 1,000 bbls/d January 1 to December 31 CDN$ WCS CDN$ 49.50/bbl Swap
Oil 500 bbls/d January 1 to June 30 CDN$ WCS CDN$ 40.00/bbl to 52.50/bbl Collar
Oil 500 bbls/d January 1 to December 31 CDN$ WCS CDN$ 40.00/bbl to 47.00/bbl Collar
Oil 1,000 bbls/d January 1 to December 31 US$ WTI US$ 60.00/bbl Sold Call
Oil 500 bbls/d January 1 to December 31 US$ WTI US$ 70.00/bbl Sold Call

Operating costs and transportation costs in Q3 2016 were $13.6 million, or $14.24 per boe, compared to $12.8 million or $21.01/boe in Q3 2015. The increase in operating costs reflects higher production volumes. The decrease in per unit operating costs reflects the lower cost of production related to our Onion Lake thermal operations.

Higher production revenues contributed to an increase in funds flow from operations during the third quarter. Funds flow from operations increased to $14.2 million during the quarter compared to $10.2 million for the same period in 2015.

During the third quarter we continued to use our operating cash flows to reduce our debt. Bank debt as at September 30, 2016 was $67 million, $21 million lower than at the beginning of the year. Net debt (bank debt less working capital) at September 30 was $64 million. The total credit facilities available to the Company are currently $117.5 million. The lenders next review of these facilities is expected to be completed by November 30, 2016.

The 2016 third quarter report to shareholders, including the financial statements, management's discussion and analysis and notes to the financial statements are available on the Company's website ( or SEDAR (


Our plans are largely unchanged from guidance previously provided in the Q2 and Q1 updates. As a result of higher oil prices our estimated funds flow from operations for the year is expected to be between $42 and $45 million, up from our Q2 guidance of $35 to $40 million and year-end 2016 debt levels are anticipated to be between $52 and $55 million, down from our Q2 guidance of $60 to $65 million. We anticipate average oil and gas production in 2016 to be approximately 10,000 boe/d, an increase from our Q2 guidance of between 9,000 and 10,000 boe/d. The increase is attributable to the positive performance of the Onion Lake thermal project. Our plan for 2016 was to limit capital spending and use our operating cash flows to pay down debt and as a result capital spending for the year is now expected to be between $7 and $10 million.

Non-GAAP Measures

In this news release, the Company uses terms "funds flow from operations", "netback" and "net debt" and "net debt to funds flow ratio". These terms do not have standardized meanings as prescribed by GAAP and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. These terms are used by the Company to analyze operating performance, leverage and liquidity and to provide shareholders and investors with additional information to measure the Company's performance and efficiency and its ability to fund a portion of its future activities and to service any long-term debt.

The following table reconciles non-GAAP measurement "Funds flow from operations" to "Cash flow from operating activities", the nearest GAAP measure. "Funds flow from operations" represents cash flow from operating activities (the closest GAAP measure) expressed before decommissioning costs incurred and changes in non-cash working capital.

Three months ended
September 30,
Nine months ended
September 30,
($000s) 2016 2015 2016 2015
Cash flow from operating activities 16,441 14,216 27,412 50,165
Add (deduct):
Decommissioning costs incurred 38 117 554 379
Changes in non-cash working capital related to operations (2,277) (4,177) 1,011 (12,480)
Funds flow from operations 14,202 10,156 28,977 38,064

"Netback" is calculated as oil and gas revenues less royalties, production costs, transportation costs and realized gains/losses on risk management contracts, divided by total production for the period on a boe basis. "Net debt" represents long term debt less working capital. "Net debt to funds flow ratio" represents net debt divided by funds flow from operations (Q3 2016 multiplied by 4 to annualize the amount).

Contingent Resources

Contingent resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. There is no certainty that it will be commercially viable to produce any of the contingent resources. Best estimate (P50) is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. Please refer to our Annual Information Form for a more detailed discussion of our contingent resources and the contingencies for each property.

All dollar amounts throughout this new release are stated in Canadian dollars unless otherwise noted.

Forward-looking Statements

This release contains certain forward-looking statements and forward-looking information (collectively referred to as "forward-looking statements") within the meaning of applicable Canadian securities laws. All statements other than statements of historic fact are forward-looking statements. Forward-looking statements are typically identified by such words as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "potential", "targeting", "intend", "could", "might", "should", "believe" or similar words suggesting future events or future performance.

In particular, but without limiting the foregoing, this report contains forward-looking statements pertaining to our business plans and strategies; capital expenditure and drilling programs including timing and estimated capital costs for the expansion of the Onion Lake thermal EOR project, the expectation that Blackrod will be developed in phases, with the first phase likely to be between 10,000 and 20,000 bbl/d, the estimated reserves and contingent resources associated with the Blackrod leases and all information in the Guidance section of this news release.

The forward-looking statements in this document reflect certain assumptions and expectations by management. The key assumptions that have been made in connection with these forward-looking statements include the continuation of current or, where applicable, assumed industry conditions, the continuation of existing tax, royalty and regulatory regimes, commodity price and cost assumptions, the continued availability of cash flow or financing on acceptable terms to fund the Company's capital programs, the accuracy of the estimate of the Company's reserves and resource volumes and that BlackPearl will conduct its operations in a manner consistent with past operations. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties which could cause actual results to differ materially from those contained in forward-looking statements. These factors include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent; risks related to the exploration, development and production of crude oil, natural gas and NGLs reserves; general economic, market and business conditions; substantial capital requirements; uncertainties inherent in estimating quantities of reserves and resources; extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time; the need to obtain regulatory approvals on projects before development commences; environmental risks and hazards and the cost of compliance with environmental regulations; aboriginal claims; inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions; potential cost overruns; variations in foreign exchange rates; diluent supply shortages; competition for capital, equipment, new leases, pipeline capacity and skilled personnel; uncertainties inherent in the SAGD bitumen and ASP recovery processes; credit risks associated with counterparties; the failure of the Company or the holder of licenses, leases and permits to meet requirements of such licenses, leases and permits; reliance on third parties for pipelines and other infrastructure; changes in royalty regimes; failure to accurately estimate abandonment and reclamation costs; inaccurate estimates and assumptions by management; effectiveness of internal controls; the potential lack of available drilling equipment and other restrictions; failure to obtain or keep key personnel; title deficiencies with the Company's assets; geo-political risks; risks that the Company does not have adequate insurance coverage; risk of litigation and risks arising from future acquisition activities. Further information regarding these risk factors and others may be found under "Risk Factors" in the Annual Information Form.

Undue reliance should not be placed on these forward-looking statements. Readers are cautioned that the actual results achieved will vary from the information provided herein and the variations could be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive. Consequently, there is no assurance by the Company that actual results achieved will be the same in whole or in part as those set out in the forward-looking statements. Furthermore, the forward-looking statements contained in this document are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

The information in this release is subject to the disclosure requirements of BlackPearl Resources Inc. under the EU Market Abuse Regulation and/or the Swedish Securities Market Act. This information was publicly communicated on November 3, 2016 at 3:30 p.m. Mountain Time.

Contact Information:

BlackPearl Resources Inc.
John Festival
President and Chief Executive Officer
(403) 215-8313

BlackPearl Resources Inc.
Don Cook
Chief Financial Officer
(403) 215-8313

BlackPearl Resources Inc.
Robert Eriksson
Investor Relations Sweden
+46 701-112615